1. Field of the Disclosure
The present disclosure generally relates to systems and methods for testing drilling fluids for drilling operations. More particularly, the present disclosure relates to methods and systems for determining sealing characteristics of fluid loss control materials and optimizing drilling fluids using such particles.
2. Background Art
During the drilling of a wellbore, various fluids are typically used in the well for a variety of functions. The fluids may be circulated through a drill pipe and drill bit into the wellbore, and then may subsequently flow upward through wellbore to the surface. During this circulation, the drilling fluid may act to remove drill cuttings from the bottom of the hole to the surface, to suspend cuttings and weighting material when circulation is interrupted, to control subsurface pressures, to maintain the integrity of the wellbore until the well section is cased and cemented, to isolate the fluids from the formation by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the wellbore, to cool and lubricate the drill string and bit, and/or to maximize penetration rate.
In most rotary drilling procedures the drilling fluid takes the form of a “mud,” i.e., a liquid having solids suspended therein. The solids function to impart desired rheological properties to the drilling fluid and also to increase the density thereof in order to provide a suitable hydrostatic pressure at the bottom of the well. The drilling mud may be either a water-based or an oil-based mud.
Drilling muds may consist of polymers, biopolymers, clays and organic colloids added to a water-based fluid to obtain the required viscosity and filtration properties. Heavy minerals, such as barite or calcium carbonate, may be added to increase density. Solids from the formation are incorporated into the mud and often become dispersed in the mud as a consequence of drilling. Further, drilling muds may contain one or more natural and/or synthetic polymeric additives, including polymeric additives that increase the rheological properties (e.g., plastic viscosity, yield point value, gel strength) of the drilling mud, and polymeric thinners and flocculents.
Polymeric additives included in the drilling fluid may act as fluid loss control agents. Fluid loss control agents, such as starch, prevent the loss of fluid to the surrounding formation by reducing the permeability of filter cakes formed on the newly exposed rock surface. In addition, polymeric additives are employed to impart sufficient carrying capacity and thixotropy to the mud to enable the mud to transport the cuttings up to the surface and to prevent the cuttings from settling out of the mud when circulation is interrupted.
As such, many drilling fluids may be designed to form a thin, low-permeability filter cake to seal permeable formations penetrated by the drill bit. The filter cake is essential to prevent or reduce both the loss of fluids into the formation and the influx of fluids present in the formation. Upon completion of drilling, the filter cake may stabilize the wellbore during subsequent completion operations such as placement of a gravel pack in the wellbore. Filter cakes often comprise bridging particles, cuttings created by the drilling process, polymeric additives, and precipitates. One feature of a drilling fluid is to retain these solid and semi-solid particles as a stable suspension, free of significant settling over the time scale of drilling operations.
Once the drilling fluid is lost into the formation, it becomes difficult to remove. Calcium and zinc-bromide brines can form highly stable, acid insoluble compounds when reacted with the formation or substances contained therein. This reaction may reduce the permeability of the formation to any subsequent out-flow of the targeted hydrocarbons. The most effective way to prevent such damage to the formation is to limit fluid loss into the formation.
Thus, providing effective fluid loss control is highly desirable to prevent damaging the formation in, for example, completion, drilling, drill-in, displacement, hydraulic fracturing, work-over, packer fluid emplacement or maintenance, well treating, or testing operations. In certain drilling environments, the formation may be exceptionally prone to damage from fluid loss. Examples of such drilling operations may include depleted zone drilling.
Depleted drilling zones may be especially prone to fractures (i.e, cracks and disruptions in a formation that may be either naturally formed or induced). Fracturing during the drilling operation, also known as induced fracturing, typically occurs in permeable rocks such as sandstone and carbonates or within impermeable rock typified by shale formations. Induced fracturing is of particular concern when drilling into depleted zones where a drop in pore pressure is anticipated as the reserves decline. In these situations, drilling then becomes more of a technical challenge as the mud weight required to support a section may exceed the tensile strength, or fracture resistance, of the formation. This in turn could lead to increased drilling fluid losses and increased well costs.
In order to prevent fluid loss and increased well costs a number of tests and equipment for testing drilling fluids and formation for fluid loss and sealing characterstics have been developed. Previous work on the fracture studies resulted in the development of an apparatus that could mimic fractures in impermeable rock. This particular equipment included an opposed piston design that used two matched 2.5-inch diameter corrugated aluminum platens to simulate formation fracture faces. The fracture gap could be set using three screws. Furthermore, the fracture faces were sandblasted in order to increase the level of surface irregularities and friction allowing for better particle adhesion and to encourage bridging.
The operation of the impermeable fracture test apparatus involved pumping a test fluid containing fluid loss control materials through the open fracture of a fracture cell and into a fracture tip accumulator cell. The test fluid was pumped at a constant flow rate while maintaining constant fracture tip and fracture closure pressures. The effects of the fluid and/or fluid loss control material on a fracture of pre-determined width could then be determined by monitoring the mud pressure, which is variable and dependent upon the quality of fracture seal.
While the test apparatus allowed an operator to gain some minimal understanding of how fluid loss control materials contributed to sealing impermeable fractures, the equipment was limited to only measuring a fluid loss at the fracture tip.
Accordingly, there exists a continuing need for systems and methods of testing and optimizing drilling fluids and/or fluid loss control materials for drilling in permeable and impermeable formation.